The present invention relates to the field of oil pumping systems and, more particularly, to a system and method for the cost-effective production of oil from economically marginal, low volume oil wells.
Three pumping methods are typically used in low pressure or no-pressure wells for lifting crude oil and water from subsurface formations to the surface. For low volume wells at relatively shallow depths, nearly all wells are pumped using beam pumping units. Beam pumping units trace their origin to xe2x80x9cpitcher pumpsxe2x80x9d found on farms in rural areas in Europe and the United States in the 18th and early 19th century. For residential and commercial water supply, such pitcher pumps have largely been replaced by water distribution systems from municipal sources. However, the principle of using a rod to reciprocate a positive displacement pump element found application in lifting crude oil and produced water in oil fields and has been one of the three major lift methods employed world wide since 1912.
Today, beam pumping units used in oil production are part of a pumping system that employs pump off controllers that have either timers or other sensors located near the well head. When timers are employed, the pump is operated periodically at a rate that approximates the rate the well fills from natural drainage from the formation. Pump off controllers based on weight or power sensors operate the pump until a change in pump load is detected indicating that the pumping operation is no longer lifting fluid.
Many attempts have been made to improve the overall efficiency of beam pumping units by improving the pump off control system. However, these systems continue to rely on measurements of the surface observable characteristics of the pump or on surface control of the driving motor. Various improvements to these two basic techniques have been proposed. For example, U.S. Pat. No. 5,984,641 to Bevan, et al. teaches a controller for controlling the pump unit of an oil well which includes a sensor having probes in the flow of oil from the well bore to determine oil flow rate. A pump control signal is generated in response to the flow rate, and the pump control signal varies a predetermined parameter of a pumping unit during operation.
Other systems operate on other surface measured characteristics such as pump rod loading, such as for example U.S. Pat. No. 3,824,851 to Hahar, and drive motor power. In contrast, Adams, Jr.; in U.S. Pat. No. 4,570,718; proposed a system for controlling production in an oil well which included a surface-located controller for activating the means for causing reciprocation of the sucker rod of a beam pumping unit. A sensor was secured to the outer surface of the production tubing near the lower end of the tubing. The sensor comprised a radioactive source spaced from a radioactivity detector such that oil at that level would fill the space. Oil in the space would modify the amount of radioactivity sensed by the detector, and provide some indication of the level of oil in the well.
A principal drawback of such systems is that they draw an inordinate amount of power in order to operate, and when such wells produce only limited quantities of oil, they quickly become uneconomical. When such marginal or low volume wells cannot justify the cost of the installation and operation of the lifting system, they are typically closed in, even though there may be large quantities of hydrocarbons left underground.
Low volume wells typically produce less than 20 barrels (xe2x80x9cbblxe2x80x9d) of total fluid (oil and water) per day. Lifting 20 bbl of fluid a height of 1000 feet over a period of 20 hours typically requires 5 to 20 Hp in beam pumping systems. Further, such beam pumping units suffer increasing power requirements to operate the rod string, stuffing box, and to overcome viscous forces of the fluid at greater depths. In low volume wells, power losses in the stuffing box can exceed the actual power required to lift the fluid. Since production tubing is rarely sufficiently straight to allow the rod string to reciprocate without contacting the tubing, significant wear on both production tubing and the rod string is common, even with rod guides installed on the sucker rod.
In conventional beam pumping systems, the fluid is removed from a well in the annulus between the reciprocating rod string and a conduit of production tubing attached to the downhole pump. Geyer; in U.S. Pat. No. 4,830,113; recognized this phenomenon and proposed a small down hole pump and a relatively small motor as a replacement for the existing system. The Geyer system, however, met with two operational problems. First, the Geyer system required coil tubing as the production conduit. Most existing oil field tubulars consist of segments of steel pipe which precludes the cable installation method of Geyer as the tubular must be separated into segments during removal from the well. In contrast, the present invention uses a method which allows installation of the power cable after the production string is installed into the well. Second, the Geyer system provided no improvement over conventional provisions for the control of the down hole apparatus. Detection of the pump off condition in Geyer was accomplished by sensing changes in the required power. The present invention, however, uses sensors located near the pump to determine the level and condition of the fluid to be pumped. By employing a closed loop control scheme, the fluid level can be maintained within a specified range above the pump.
Many different pump off controllers have been proposed in the art, and many such controllers have been installed for production from low volume wells. For low volume wells which are typically pumped with beam pumps, pump off control methods depend on recognition of pump loading either through direct measurement of forces on the sucker rod or these methods rely on various schemes to control the pump using the motor loading. In some systems, a direct measurement of well fluid level is attempted, such as in Adams, Jr. as previously described. In these systems, either a conductive liquid is required and the only liquid level that can therefore be detected is produced brine or a single physical parameter is measured which leads to ambiguity in the determination of liquid level. This ambiguity results from the varying makeup of produced fluids from a pumping well, including often unpredictable mixtures of oil, water, brine of varying salinity, and various gases.
In some areas a well may produce a frothy crude oil mixed with oil field brine. In this type of production, it is impossible to determine the liquid level below the foam using reflective acoustic measurement because of the attenuation of the transmitted acoustic signal in the foam. Entrained gas in the froth above the oil/water liquid level also has an unpredictable effect on both velocity and amplitude of the transmitted acoustic signal and thus renders such measurements inaccurate.
Attempts to unambiguously determine the liquid level by measurement of a dielectric constant have also failed because the produced fluid typically contains three constituents in a pumped off well. These constituents are gas, oil, and water of varying salinity. Combinations of the dielectric properties of these three constituents may result in multiple combinations having the same dielectric constant.
Attempts to directly measure electron density by gamma ray attenuation have encountered limitations resulting from the varying density of produced crude oils over the life of an oil well. Occasionally, produced crude oils have the same density as water. And, over the life of an oil well the effervescence of produce crude may change. This results in a variation of oil density and ultimately the ability to determine fluid level from density measurements alone. It may be possible to employ neutron diffusion differences to unambiguously determine hydrogen density and infer a liquid level. However, this type of measurement system would require either a long lived chemical radiation source or installation of a neutron generator near the desired liquid level. Chemical radiation sources pose a long term contamination risk making this solution unacceptable and current neutron generators have too short a life to be considered for semi-permanent installation.
Thus, there remains a need for an efficient means of pumping oil from low volume wells. Such a system should preferably include a means for unambiguously determining liquid level within the well, in order to pump from the well at a rate to maintain approximately constant liquid level.
The present invention addresses these and other drawbacks in the art by providing a small positive displacement pump below the fluid interface in a low volume oil well. The system includes at least a pair of sensors in a sensor array that is positioned above the pump and near the fluid interface to unambiguously determine liquid level. By maintaining the pumping rate of the positive displacement pump below that required to lower the liquid level to the pump, the pump will not unload and pump power requirements are reduced to a nearly constant low rate. In addition, the pump off control function is accomplished by a microprocessor which is mounted adjacent to the downhole sensor array. This location allows simple direct control of the downhole electric motor and eliminates the requirement that a control element be placed on the surface far from the pump.
It is therefore an object of the present invention to reduce the cost of producing liquids from low volume wells. In accordance with this invention, fluids such as water and/or oil and/or natural gas are produced out of the well within a substantially annular space between a conduit typically formed from a string of production tubulars and the power delivery cable. The power delivery cable is included in an armored wireline and provides power to the pump, the pump off controller, and the sensors.
In high volume wells typically pumped using centrifugal pumps, electrical power is provided to the downhole motor via electrical cable suspended in the annulus between the production tubing and the well casing. This arrangement is advantageous for two reasons. First, the production tubing is typically assembled in joints approximately 30 feet in length. It is more convenient to pass the cable into the well from a continuous spool when installing the production tubular than to install the cable within the production tubular by pulling the entire length of cable through each joint of the production tubular string during installation. Second, the rate of production of fluid from wells pumped using downhole centrifugal pumps is sufficiently high that the flow of fluid from the well is turbulent from the exit of the pump to the surface. With this flow velocity, friction on a cable suspended within the production tubular is significant and will result in vibration and destruction of the connecting power cable. Installation of power connections at multiple positions within the production tubular have been attempted without commercial success due to compounding of the potential for failure with each of multiple connections.
It is therefore another object of the present invention to provide low cost installation of an oil pumping system that is compatible with existing hardware. This means using existing well production tubulars and a way to the power cable into a tubing string without the laborious task of threading cable through each joint before installing the joint into the well. To this end, a single xe2x80x9cwet connectxe2x80x9d of the type typically used in connection of instrument packages during directional well drilling applications is used to make a single downhole connection to the pump and sensor assembly using a cable suspended within the production tubular. Because the system of the invention is intended to support low production rates, the velocities obtained by pump fluids are typically very low, typically less than 0.25 ft/sec. At these rates, viscous fluids of the type this invention addresses approach xe2x80x98creep flowxe2x80x99 and friction at the surface of the production tubular or at the surface of the power cable is minimal and therefore, so is the tendency for vibrational failure of the power cable.
It is a further object of the invention to provide local, continuous pump off control so that the level of fluid in the well is held at a nearly constant level above the pump and below the static liquid level supplied by formation pressure. To accomplish this, a minimum of two sensors are placed within a sleeve that surrounds the production conduit. These sensors are preferably a fluid density gauge and a capacitance gauge. However, sensors that measure a physical parameter of the fluid column that varies so that the sensors can differentiate between oil and/or water level with varying quantities of emulsified gas or foam can be used. In the case of the fluid density sensor, an elongated container of a radioactive mineral or other radioactive material is mounted axially on the sleeve. This container is parallel to an open channel open to the annulus between the production conduit and the well casing and through which the well bore fluid may pass.
A long radiation detector, for example a Geiger-Mueller (G-M) counter, is parallel to the open channel and on the opposite side of the open channel from the elongated container containing the radioactive material. AG-M counter is a radiation detection and measuring instrument which consists of a gas-filled tube containing electrodes, between which there is an electrical voltage, but no current flowing. When ionizing radiation passes through the tube, a short, intense pulse of current passes from the negative electrode to the positive electrode and is measured or counted. The number of pulses per second measures the intensity of the radiation field. By accurate calibration of the radiation attenuation across the channel caused by the liquid and froth in the channel, the average electron density of the fluid within the channel can be determined. For most mixtures of crude oil, water, and natural gas this electron density is directly correlatable to a narrow range of liquid levels.
Similarly, a second open channel is constructed axially along the sleeve adjacent to this channel. Two insulated plates of a capacitor are installed in this second channel. By sensing the change in capacitance between these plates, the level of various liquids contained between the plates is determined. Because the measurements of these two physical properties, radiation and capacitance, have no effect on each other, it has been found convenient to use a single open channel and measure both electron density and dielectric constant across this single channel.
Raw measurements from these two sensors are reported directly to a microprocessor used as an imbedded controller and located in a chamber within the same sleeve as the sensors. A variable power supply, responsive through the algorithm operating on the microprocessor, whose parameters are determined by the sensor input from the two sensors, is used to provide power to the electric motor which is used to provide power to a multi-stage positive displacement pump. By this method the liquid level within a pumping well can be maintained within the length of the sleeve containing the sensors and microcontroller.
Another object of the present invention is to allow continuous pumping of a well to keep the liquid level and hence the back pressure on the formation nearly constant. To accomplish this, it is necessary to employ a pump that does not compress gas directly back into the liquid hydrocarbon only to allow the associated volumetric contraction to xe2x80x9cgas lockxe2x80x9d the pump. Volumetric contraction of mixtures of oil and gas can be significant and at various times the well bore fluid may be 100% water based brine which is effectively uncompressible. To cover the widest variety of well production characteristics in low volume wells, a multistage positive displacement pump is preferred. To accommodate the variation in fluid compressibility, each subsequent stage of the positive displacement pump must be reduced in volumetric capability from the previous stage. However, to accommodate the nearly incompressible brines sometimes produced, an interstage pressure relief bypass is required.
These and other features of the invention will be apparent to those of skill in the art from a review of the following detailed description along with the accompanying drawings.